Injectivity and Gravity Override in Surfactant-Alternating-Gas Foam Processes

Abstract

Surfactant-alternating-gas (SAG) foam processes can in principle combine high gas injectivity with low mobility at the front of the foam bank. Such a process can give the appearance of extremely shear-thinning behavior, in that the pressure gradient is remarkably low near the well. However, this appearance is due to the effects of declining water saturation near the well, not to the effects of high near-well flow rates on foam mobility. Preliminary simulation results suggest that as long as mobility is low in a region away from the well, high gas mobility near the well need not lead to gravity override. Indeed, since increased injectivity allows higher injection rates and thereby increased flow rates and pressure gradients away from the well, increased mobility near the well may help to reduce the risk of gravity override. Introduction Surfactant-alternating-gas (SAG) injection has several advantages for foam enhanced-oil-recovery (EOR) projects. SAG injection minimizes contact between water and gas in surface facilities and piping, which can be important when the gas, for instance CO2, forms an acid upon contact with water. Alternating injection of small slugs of gas and fluid can promote foam generation in the near-well region. A major additional advantage of SAG injection is increased gas injectivity: as water is displaced from the near-well region during gas injection, foam weakens there, gas mobility rises and injectivity increases. The increase reflects the enormous importance of the near-well region to injectivity in radial flow. This advantage is especially important in relatively low-permeability formations without much excess injectivity If injectivity is low during gas injection, gas injection rate must be reduced or fracturing may result. The advantage of increased injectivity is deceptive, of course, if foam has disappeared from the entire formation rather than merely weakened in the near-well region. There are several reasons for concern that this may occur: First, it is claimed that foam generation requires high flow velocities attainable only in the near-well region, though others disagree. Thus, the reasoning goes, if the near-well region dries out during gas injection and foam generation ceases there, no foam can be created anywhere during this period, and the foam process stalls or collapses. The minimum flow rate for foam generation depends on gas-liquid surface tension, which is much lower for CO2 foams than for N2 foams used in many laboratory studies of foam generation. Therefore this effect may not be important for CO2 foams. Moreover, exceeding the minimum flow rate for "generation" is not necessary if only a relatively weak, "leave-behind" foam is required. The second reason for concern is that high-mobility gas near the well may simply finger through or override lower- mobility foam away from the well during gas injection. Recent simulation results suggest that the ability of foam to overcome gravity override depends in part on a dimensionless gravity number Ng that depends on local pressure gradient P: [1] where is the difference in densities between gas and aqueous phase (referred here throughout as "water"), and g is gravitational acceleration. Local pressure gradient is related to local flow rates and foam strength through Darcy's law: [2] where uw and ug are local volumetric fluxes, i.e., superficial or "Darcy" velocities, of water and gas; k is permeability; is local total relative mobility; w is water viscosity; and krw is water relative permeability, a function of water saturation Sw. Large values of Ng promote gravity override, which can occur even in the presence of foam at low flow rate and P. The recent simulations concerned continuous foam injection into a two-dimensional (2D), rectangular, homogeneous reservoir, in which P is uniform and constant within the foam bank. The exact criteria for gravity override in SAG displacements in radial flow, in which P is neither uniform nor constant, are not yet clear. P. 521

Effect of Surfactant Partitioning on Mobility Control During CO2 Flooding

“…Several potential injection strategies for a robust foam process have been studied (Rossen et al 1995;Shi 1996;Shi and Rossen 1998;Renkema and Rossen 2007;Rossen and Shen 2007;Jamshidnezhad et al 2008;Rossen et al 2010). A water-alternating-CO 2 injection has been most commonly used in field-scale foamprocess application (Lawson and Reisberg 1980;Xu and Rossen 2004), whereas simultaneous injection of these two phases has been the main injection scheme for a laboratory-scale foam study because the implementation of the latter strategy has encountered some difficulties such as operational constraints and a severe reduction of well injectivity.…”

Experimental Evaluation of Carbon Dots Stabilized Foam for Enhanced Oil Recovery

“…Foam was generated in the rock samples using surfactant alternating gas (SAG) injection method. The SAG method is generally believed to yield better foam injectivity and a stronger foam compared to other methods . The core-flood experiments (Figure S2) were conducted at a confining pressure of 2200 psi, a back-pressure of 1450 psi, and a constant oven temperature of 45 °C.…”

Simulations of Chemical and Microbial Enhanced Oil Recovery Methods

“…During foam injection, low gas mobility drives down water saturation within the foam bank, as is well known in the foam-IOR literature. [23][24][25][26][27] A surfactant-slug injected following foam can trap virtually all of this gas in place, retaining low liquid mobility and effective diversion during subsequent liquid injection. 28,29 Although supported by laboratory data and verified by application to thousands of acid-diversion treatments worldwide, 30 the effectiveness of this conformance process requires modeling on a reservoir scale.…”